WO1993021501A1 - Debitmetre massique pour hydrocarbures - Google Patents

Debitmetre massique pour hydrocarbures Download PDF

Info

Publication number
WO1993021501A1
WO1993021501A1 PCT/US1993/003298 US9303298W WO9321501A1 WO 1993021501 A1 WO1993021501 A1 WO 1993021501A1 US 9303298 W US9303298 W US 9303298W WO 9321501 A1 WO9321501 A1 WO 9321501A1
Authority
WO
WIPO (PCT)
Prior art keywords
mixture
measuring
signal representing
hydrocarbon
density
Prior art date
Application number
PCT/US1993/003298
Other languages
English (en)
Inventor
Scott Gaisford
Original Assignee
Multi-Fluid, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Multi-Fluid, Inc. filed Critical Multi-Fluid, Inc.
Priority to EP93911615A priority Critical patent/EP0635118B1/fr
Priority to AU40481/93A priority patent/AU665919B2/en
Priority to DE69333602T priority patent/DE69333602D1/de
Priority to BR9306231A priority patent/BR9306231A/pt
Priority to JP51846993A priority patent/JP3228514B2/ja
Priority to AT93911615T priority patent/ATE274689T1/de
Publication of WO1993021501A1 publication Critical patent/WO1993021501A1/fr
Priority to NO19943697A priority patent/NO318642B1/no
Priority to FI944703A priority patent/FI109236B/fi
Priority to NO943809A priority patent/NO943809D0/no

Links

Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/74—Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/76—Devices for measuring mass flow of a fluid or a fluent solid material
    • G01F1/86—Indirect mass flowmeters, e.g. measuring volume flow and density, temperature or pressure
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N27/00—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means
    • G01N27/02—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating impedance
    • G01N27/22—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating impedance by investigating capacitance
    • G01N27/221—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating impedance by investigating capacitance by investigating the dielectric properties
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
    • G01N33/26—Oils; Viscous liquids; Paints; Inks
    • G01N33/28—Oils, i.e. hydrocarbon liquids
    • G01N33/2823—Raw oil, drilling fluid or polyphasic mixtures
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/36—Analysing materials by measuring the density or specific gravity, e.g. determining quantity of moisture

Definitions

  • This invention relates to the field of meters and particularly to meters for continuously measuring the composition and mass flow rate of mixtures containing hydrocarbons.
  • Many types of measurement apparatus have been proposed and are being used for continuously measuring water content, density, or composition of hydrocarbon or hydrocarbon and water mixtures. But most suffer from a number of limitations caused by difficulties with measuring mixtures containing liquid and gas or difficulties associated with variations in the specific gravity of the hydrocarbon being measured. Measuring the composition of oil, water, and gas mixtures is one example. Meters for this purpose are typically referred to as multiphase composition meters. See U.S. Patents 4,458,524 and 4,760,742 and U.K. Patent 2,210,461.
  • the current practice in the oil industry for measuring the quantities of oil, water, and gas being produced by a given well or group of wells is to separate the components in a separator and measure the components individually.
  • the separators are large, expensive, maintenance intensive, and typically provide production information only at long intervals.
  • oil producers can dramatically improve the crude oil and natural gas production process, particularly offshore production.
  • Most proposed multiphase composition meters are designed to continuously measure the volume fractions of oil, water, and gas being produced.
  • the composition meter can be combined with a flowmeter such that production rates for the three components can be calculated.
  • One variety of proposed multiphase composition meter combines a dielectric constant measurement means with a density measurement means. See, for example, U.S. Patent 4,458,524. These devices take advantage of the different dielectric constant and densities of oil, water r and gas, respectively, to determine their volume fractions. Temperature and pressure sensors are included in the metering package to facilitate these calculations.
  • Another important measurement problem in the oil industry is the accurate measurement of the water content of liquid crude oil streams.
  • the water content directly affects the price paid for crude oil.
  • Many devices have been developed to continuously measure the water content. See U.S. Patents 3,498,112 and 4,862,060 for examples.
  • the most commonly used measurement device for this application is a capacitance meter which measures the dielectric constant of the mixture to determine its water content.
  • Many meters besides capacitance meters utilize dielectric measurements for measuring the water content of crude oils, including various microwave meters.
  • a common problem for all of these devices is that the density and dielectric constant of the crude oil vary over time. These variations result directly in significant measurement error.
  • a suitable multiphase composition meter would then determine the volumetric fraction and the density of the hydrocarbon, i.e. the mass, of the hydrocarbon material in a multiphase mixture and the water content of the mixture. Armed with this information plus flow rate information, the user can more correctly determine how much oil and gas are being produced at standard conditions.
  • a multiphase hydrocarbon mass meter to be used in crude oil or natural gas multiphase production lines is considered desirable.
  • One embodiment of this invention combines a dielectric measurement means, a density measurement means, and a temperature measurement means to determine the instantaneous hydrocarbon mass flowing through the meter.
  • the present invention utilizes a heretofore unknown relationship between the density of a hydrocarbon, whether liquid, gas or a combination thereof, and its dielectric constant.
  • an improved meter to measure water content i.e., a water cut meter
  • a water cut meter which consists of a combination of a dielectric measurement means, a density measurement means, and a temperature measurement means makes it possible to continuously correct the water cut meter for variations in the oil's dielectric properties.
  • Combining this improved water cut meter with a flow meter gives the additional possibility of continuously totalizing the production rates of the oil and water in terms of volume or mass per unit of time and continuously measuring the crude oil quality which is directly related to its density.
  • This improved water cut meter is useful with crude oils, gas condensates, and liquid natural gases.
  • Figures 1 and 2 are plots of the square root of the dielectric constant versus hydrocarbon density for liquid hydrocarbons and hydrocarbon/gas mixtures, respectively.
  • Figure 3 is a block diagram of a multiphase hydrocarbon mass meter constructed in accordance with the present invention.
  • Figure 4 is a block diagram of a hydrocarbon mass flow meter constructed in accordance with present invention.
  • FIG. 5 is a block diagram of an improved water cut meter constructed in accordance with the present invention.
  • FIG. 6 is a block diagram of an oil and water mass flow meter constructed in accordance with the present invention. Description of the Invention
  • 'g' is the subscript for gas
  • V Volume fraction
  • p Density
  • e dielectric constant
  • Equation 3 is any of a number of equations which describe the relationship between the dielectric constant of the mixture and the dielectric constants and volume fractions of the components. For example, one might use the Looyenga mixing relation:
  • the volume fractions V w , V 0 , and V g are to be calculated from the measured mixture density p mix and dielectric constant e-- ix .
  • the dielectric constant and densities of the three components vary with temperature and pressure. Therefore, the appropriate values must be calculated at the measurement temperature and pressure if the procedure is to work. This can be done if the physical properties of the oil, water, or gas taken separately do not change with temperature and pressure in an unpredictable fashion. But, such is " not the case.
  • Several of the hydrocarbon components can be in either the liquid or gaseous state at higher pressures; therefore, the oil and gas densities and dielectric constants are unknown at high pressure.
  • the method and apparatus of this invention differ from this standard approach by considering the oil and gas components as a single hydrocarbon material with an unknown density and dielectric constant.
  • the invention utilizes the principle that the dielectric constant and density of hydrocarbons produced by oil wells can be directly related to one another. This is true if the hydrocarbon is liquid, gas, or a combination thereof.
  • Figure 1 shows the square root of the measured dielectric constant versus density for a variety of hydrocarbon liquids at 15°C. A linear curve fit is also shown in the figure. The lowest density hydrocarbon is pentane with a density of approximately 0.67 g/ml. The highest density hydrocarbon is a heavy crude oil having a density of approximately 0.92 g/ml. Included among the hydrocarbons shown in Figure 1 are crude oils, gas condensates, and individual hydrocarbon fractions. As Figure 1 shows, the square root of the dielectric constant and the density of hydrocarbon liquids are linearly related with the zero density intercept being 1. In other words, as the density approaches zero, the dielectric constant approaches 1 which is the dielectric constant of vacuum which has a density of zero.
  • Figure 2 shows the square root of the dielectric constant as a function of density for a crude oil mixed with varying amounts of gas.
  • the volumetric fraction of gas extends from 0 to 55%.
  • the relationship between the square root of the dielectric constant and the density is linear and the zero density intercept is 1.
  • the dielectric constant of the gas is approximately equal to 1.0005.
  • hydrocarbon dielectric constant and density can be used to avoid the problems associated with measuring liquid and gas hydrocarbon fractions at high pressure.
  • the multiphase meter can instead measure hydrocarbon and water fractions and the density of the hydrocarbon; i.e., the multiphase hydrocarbon mass meter continuously measures the mass of the hydrocarbon being produced.
  • Equations 1 to 3 the multiphase hydrocarbon mass meter would use a measurement procedure illustrated by the following relations:
  • Equation 4 could be any of a number of equations which describe the relationship between the dielectric constant of a mixture and the dielectric constant and volume fractions of its components. The following relation could be used for example:
  • Equations 4-6 there are three unknowns: V hyd , p hyd , and e hyd . But the dielectric constant and the density of the hydrocarbon can be related using the principle illustrated in Figures 1 and 2, namely:
  • 'A' is a constant which is a function of temperature.
  • 'A' is the slope of the curves shown in Figures 1 and 2.
  • V Volume fraction
  • e dielectric constant
  • Equation 11 could be any of a number of dielectric mixing laws such as:
  • the dielectric constant of the liquid hydrocarbon In order for the principle to be applied accurately, the dielectric constant of the liquid hydrocarbon must remain constant over time. Unfortunately, this is not usually the case.
  • the dielectric constant of the liquid hydrocarbon produced by individual wells varies. The situation is even more complex when the liquid being measured is the commingled flow of many different wells. For commingled flow, the dielectric constant of the hydrocarbon can change significantly as the production rates of the different feeder lines vary. This problem (among others) means that existing water cut meters do not deliver sufficient accuracy for many of the more crucial applications in the oil industry.
  • A is a constant which is a function of temperature.
  • the improved water cut is able to use the density information to adjust the dielectric constant of the crude oil as it changes over time.
  • the improved water cut meter calibrates itself for changes in the oil's dielectric properties over time. This is what is meant by self-calibrating water cut meter.
  • Multiphase Hydrocarbon Mass and Mass Flow Meter The novel relation between a hydrocarbon's density and its dielectric constant as shown in the foregoing theoretical section is used in this embodiment of the present invention as a means of determining hydrocarbon mass and mass flow rate.
  • the production stream consisting of water, crude oil, and gas, flows through a multiphase hydrocarbon mass meter generally designated by the numeral 10.
  • Apparatus 10 includes a fluid flowing conduit 20 through which the mixture passes.
  • the mixture to be measured may be conducted through conduit 20 on a continuous basis and conduit 20 may comprise part of a mixture transmission pipeline.
  • Temperature measurement means 30 measures the temperature 'T' of the mixture.
  • An optional pressure measurement means 40 measures the pressure 'P' of the mixture.
  • Apparatus 10 includes a dielectric measurement means 50 for measuring the dielectric properties 'e' of the mixture.
  • Dielectric measurement means 50 may be any of a variety of devices for measuring the dielectric properties of flowing material such as a capacitance meter or a microwave meter.
  • Apparatus 10 includes a density measurement means 60 which measures the density 'D' of the mixture. Density measurement means 60 may be any device capable of measuring the density of multiphase mixtures. One such device would be a gamma densitometer.
  • Temperature measurement means 30, pressure measurement means 40, dielectric measurement means 50, and density measurement means 60 are connected to multiphase hydrocarbon mass measurement means 70 and provide signals corresponding to the measured T, P, e, D values.
  • Multiphase hydrocarbon mass measurement means 70 calculates the correct density and dielectric constant for the water from the measured temperature (and pressure) . From these vales and e and D, multiphase hydrocarbon mass measurement means 70 provides an indication of the volumetric water content, the volumetric hydrocarbon content, and the hydrocarbon density. The product of the hydrocarbon density and the hydrocarbon volumetric content is equal to the hydrocarbon mass 'M' .
  • multiphase hydrocarbon mass meter 80 is connected to a flow rate measurement means 110 with a pipe section 100.
  • the combined apparatus is a multiphase hydrocarbon mass flow meter and is designated as 120.
  • the multiphase mixture can flow freely through the multiphase hydrocarbon mass flow meter 120.
  • Flow rate measurement means 100 measures the flow rate V of the mixture as it passes and provides a corresponding flow rate signal to multiphase hydrocarbon mass measurement means 90.
  • Multiphase hydrocarbon mass measurement means 90 provides an indication of the hydrocarbon mass flow rate in accordance with the received signal V and the measured value M.
  • measurement means 70 or 90 could take on many forms. Different combinations of analog to digital converters, digital to analog converters, comparators, look up tables, microprocessors, etc., could be used to determine the instantaneous hydrocarbon mass and mass flow rate from the input signals. Accordingly, it should be clearly understood to anyone skilled in the art that the form of the invention described above and shown in the figures is general in nature and not intended to limit the scope of the invention to any specific component measurement means within the scope and spirit of the appended claims.
  • Self-Calibrating Water Cut Meter The novel relation between a hydrocarbon's density and its dielectric constant as shown in the theoretical section is used in this embodiment of the present invention as a means of determining the water cut corrected for the changing dielectric constant of the liquid hydrocarbon. In addition, the relation makes possible the continuous determination of the density of the hydrocarbon, corrected for the water content, and its mass flow rate. - In illustrating this embodiment, reference will be made to Figures 5 and 6.
  • Apparatus 210 includes a fluid flowing conduit 220 through which the mixture passes.
  • the mixture to be measured may be conducted through conduit 220 on a continuous basis and conduit 220 may comprise part of a mixture transmission pipeline.
  • Temperature measurement means 230 measures the temperature 'T' of the mixture.
  • An optional pressure measurement means 240 measures the pressure 'P' of the mixture.
  • Apparatus 210 includes a dielectric measurement means 250 for measuring the dielectric properties 'e' of the mixture.
  • Dielectric measurement means 250 may be any of a variety of devices for measuring the dielectric properties of flowing materials such as a capacitance meter or a microwave meter.
  • Apparatus 210 includes a density measurement means 260 which measures the density 'D' of the mixture.
  • Density measurement means 260 may be any device capable of measuring the density of multiphase mixtures.
  • the density measurement means could be a gamma densitometer, a Coriolis Meter, or a vibrating fork densitometer, for example.-
  • Temperature measurement means 230, pressure measurement means 240, dielectric measurement means 250, and density measurement means 260 are connected to water cut measurement means 270 and provide signals corresponding to the measured T, P, e, D values.
  • Water cut measurement means 270 calculates the correct density and dielectric properties for the water from the measured temperature (and pressure) . From these values and e and D, water cut measurement means 270 provides an indication of the instantaneous water cut 'W' and the hydrocarbon density 'B' in conduit 220.
  • water cut meter 280 is connected to a flow rate measurement means 310 with a pipe section 300.
  • the combined apparatus is an oil and water mass flow meter and is designated as 320.
  • the water and oil mixture can flow freely through the crude oil mass flow meter 300.
  • Flow rate measurement means 310 measures the flow rate V of the mixture as it passes and provides a corresponding flow rate signal to water cut measurement means 290.
  • Water cut measurement means 290 provides an indication of the hydrocarbon mass flow rate in accordance with the received signal V and the measured values W and B. In fact, the hydrocarbon mass flow rate is the product of V x B x (1-W) .

Landscapes

  • Chemical & Material Sciences (AREA)
  • General Physics & Mathematics (AREA)
  • Physics & Mathematics (AREA)
  • Health & Medical Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Health & Medical Sciences (AREA)
  • Immunology (AREA)
  • Pathology (AREA)
  • Biochemistry (AREA)
  • Analytical Chemistry (AREA)
  • Fluid Mechanics (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Food Science & Technology (AREA)
  • Medicinal Chemistry (AREA)
  • Electrochemistry (AREA)
  • Measuring Volume Flow (AREA)
  • Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)
  • Transition And Organic Metals Composition Catalysts For Addition Polymerization (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Nozzles (AREA)

Abstract

Appareil de mesure utilisant le rapport direct entre la densité et la constante diélectrique de mélanges d'hydrocarbures pour améliorer de manière significative les possibilités de mesure de certains dispositifs existants utilisés dans l'industrie du pétrole. L'appareil peut s'appliquer, entre autres, à (1) un débitmètre massique d'hydrocarbure polyphasé (120) utilisé avec des mélanges polyphasés de pétrole, d'eau et de gaz, et 2) un dispositif de mesure de fraction d'eau à autoétalonnage continu, servant à déterminer la teneur en eau de courants de pétrole brut liquide.
PCT/US1993/003298 1992-04-10 1993-04-08 Debitmetre massique pour hydrocarbures WO1993021501A1 (fr)

Priority Applications (9)

Application Number Priority Date Filing Date Title
EP93911615A EP0635118B1 (fr) 1992-04-10 1993-04-08 Debitmetre massique pour hydrocarbures
AU40481/93A AU665919B2 (en) 1992-04-10 1993-04-08 A hydrocarbon mass flow meter
DE69333602T DE69333602D1 (de) 1992-04-10 1993-04-08 Massenflussmesser für kohlenwasserstoffe
BR9306231A BR9306231A (pt) 1992-04-10 1993-04-08 Aparelho para medir a massa de hidrocarboneto contida em uma corrente de produção de petróleo cru ou gás natural e para medir o teor de água em uma corrente de produção de petróleo cru líquido ou gás natural
JP51846993A JP3228514B2 (ja) 1992-04-10 1993-04-08 炭化水素質量流量計
AT93911615T ATE274689T1 (de) 1992-04-10 1993-04-08 Massenflussmesser für kohlenwasserstoffe
NO19943697A NO318642B1 (no) 1992-04-10 1994-10-04 Apparat for maling av massestrom
FI944703A FI109236B (fi) 1992-04-10 1994-10-07 Hiilivetyjen massavirtausmittari
NO943809A NO943809D0 (no) 1992-04-10 1994-10-07 Masseströmmåler for hydrokarboner

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US07/866,387 1992-04-10
US07/866,387 US5259239A (en) 1992-04-10 1992-04-10 Hydrocarbon mass flow meter

Publications (1)

Publication Number Publication Date
WO1993021501A1 true WO1993021501A1 (fr) 1993-10-28

Family

ID=25347501

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US1993/003298 WO1993021501A1 (fr) 1992-04-10 1993-04-08 Debitmetre massique pour hydrocarbures

Country Status (12)

Country Link
US (1) US5259239A (fr)
EP (1) EP0635118B1 (fr)
JP (1) JP3228514B2 (fr)
AT (1) ATE274689T1 (fr)
AU (1) AU665919B2 (fr)
BR (1) BR9306231A (fr)
CA (1) CA2117786C (fr)
DE (1) DE69333602D1 (fr)
FI (1) FI109236B (fr)
NO (2) NO318642B1 (fr)
RU (1) RU2114398C1 (fr)
WO (1) WO1993021501A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7908930B2 (en) 2005-09-23 2011-03-22 Schlumberger Technology Corporation Systems and methods for measuring multiphase flow in a hydrocarbon transporting pipeline
EP3032230A3 (fr) * 2014-12-12 2016-06-22 General Electric Company Débitmètre et procédé d'étalonnage
WO2016135506A1 (fr) * 2015-02-27 2016-09-01 M-Flow Technologies Ltd Procédé et appareil de mesure d'une composition d'un fluide multiphasique

Families Citing this family (57)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5396806A (en) * 1993-11-12 1995-03-14 Auburn International, Inc. On-line mass flow measurement in flowing two component systems
US5597961A (en) * 1994-06-27 1997-01-28 Texaco, Inc. Two and three phase flow metering with a water cut monitor and an orifice plate
NO304085B1 (no) * 1994-06-29 1998-10-19 Bjoern Dybdahl Anvendelse av et prövetakingsapparat
US5622053A (en) * 1994-09-30 1997-04-22 Cooper Cameron Corporation Turbocharged natural gas engine control system
US5613895A (en) * 1994-11-16 1997-03-25 The Guyson Corporation Of U.S.A. Particulate flow control system
US5656767A (en) * 1996-03-08 1997-08-12 Computational Systems, Inc. Automatic determination of moisture content and lubricant type
US6234030B1 (en) * 1998-08-28 2001-05-22 Rosewood Equipment Company Multiphase metering method for multiphase flow
US6164308A (en) 1998-08-28 2000-12-26 Butler; Bryan V. System and method for handling multiphase flow
EP1218728A1 (fr) * 1999-10-04 2002-07-03 Daniel Industries, Inc., Appareil et procede permettant de determiner les caracteristiques des effluents de puits de petrole dans des conditions d'ecoulement non homogenes
US6629564B1 (en) 2000-04-11 2003-10-07 Schlumberger Technology Corporation Downhole flow meter
US6405603B1 (en) 2001-03-23 2002-06-18 Joseph Baumoel Method for determining relative amounts of constituents in a multiphase flow
US6758101B2 (en) * 2001-06-04 2004-07-06 Micro Motion, Inc. Steam to carbon ratio control in steam reforming of hydrocarbons
US6636815B2 (en) 2001-08-29 2003-10-21 Micro Motion, Inc. Majority component proportion determination of a fluid using a coriolis flowmeter
US7212928B2 (en) * 2002-09-06 2007-05-01 Invensys Systems, Inc. Multi-measurement vortex flow meter
US6823271B1 (en) 2003-06-30 2004-11-23 The Boeing Company Multi-phase flow meter for crude oil
US6945122B2 (en) * 2003-06-30 2005-09-20 The Boeing Company Water cut meter for measurement of water in crude oil-magnetic
US7201068B2 (en) * 2003-06-30 2007-04-10 The Boeing Company Water cut meter for measurement of water in crude oil
US7299705B2 (en) * 2003-07-15 2007-11-27 Cidra Corporation Apparatus and method for augmenting a Coriolis meter
US7134320B2 (en) * 2003-07-15 2006-11-14 Cidra Corporation Apparatus and method for providing a density measurement augmented for entrained gas
EP1646849B1 (fr) * 2003-07-15 2008-11-12 Expro Meters, Inc. Appareil et procede pour compenser un appareil de mesure a effet coriolis
US7380438B2 (en) 2004-09-16 2008-06-03 Cidra Corporation Apparatus and method for providing a fluid cut measurement of a multi-liquid mixture compensated for entrained gas
US7389687B2 (en) 2004-11-05 2008-06-24 Cidra Corporation System for measuring a parameter of an aerated multi-phase mixture flowing in a pipe
US7334450B1 (en) 2004-11-12 2008-02-26 Phase Dynamics, Inc. Water cut measurement with improved correction for density
US20080288181A1 (en) * 2005-04-26 2008-11-20 Guillermo Amarfil Lucero Multiphase flow meter and data system
US20060247869A1 (en) * 2005-04-26 2006-11-02 Lucero Guillermo A Multiphase flow meter and data system
US7133786B1 (en) 2005-06-08 2006-11-07 Roxar Flow Management As Method and apparatus for measuring nonhomogeneous flow phase velocities
CA2613367C (fr) * 2005-06-29 2014-09-09 Micro Motion, Inc. Procede et dispositif de mesure de la densite d'un composant dans un fluide multicomposant
WO2007008793A2 (fr) * 2005-07-11 2007-01-18 Phase Dynamics Caracterisation d'un fluide polyphasique
US7457714B2 (en) 2005-07-20 2008-11-25 Phase Dynamics, Inc. Autocalibrated multiphase fluid characterization using extrema of time series
US7599803B2 (en) * 2006-04-05 2009-10-06 Phase Dynamics, Inc. Hydrocarbon well test method and system
DE102006017676B3 (de) * 2006-04-12 2007-09-27 Krohne Meßtechnik GmbH & Co KG Verfahren zum Betrieb eines Coriolis-Massendurchflußmeßgeräts
US7775085B2 (en) * 2006-04-17 2010-08-17 Phase Dynamics, Inc. High water cut well measurements with hydro-separation
RU2344288C2 (ru) * 2006-12-07 2009-01-20 Шлюмбергер Текнолоджи Б.В. Способ определения продуктивности группы скважин
US7791017B2 (en) * 2007-07-23 2010-09-07 Schlumberger Technology Corporation Method to simultaneously determine pore hydrocarbon density and water saturation from pulsed neutron measurements
US8061186B2 (en) 2008-03-26 2011-11-22 Expro Meters, Inc. System and method for providing a compositional measurement of a mixture having entrained gas
JP2010133392A (ja) * 2008-12-08 2010-06-17 Mitsubishi Heavy Ind Ltd ディーゼルエンジン燃料健全性制御システム及びディーゼルエンジン燃料健全性評価方法
IT1395937B1 (it) 2009-09-29 2012-11-02 Eni Spa Apparato e metodo per la misura della portata di una corrente fluida multifase
AU2012329604B2 (en) 2011-10-28 2016-02-04 Delaval Holding Ab Multiphase flow measurement
US9840904B2 (en) * 2012-05-11 2017-12-12 Vetco Gray Controls Limited Monitoring hydrocarbon fluid flow
RU2521623C1 (ru) * 2013-03-06 2014-07-10 Генрих Саакович Абрамов Способ идентификации скважины с измененным массовым расходом жидкости куста нефтяных скважин
RU2531500C1 (ru) * 2013-05-06 2014-10-20 Генрих Саакович Абрамов Способ идентификации скважины с измененной объемной обводненностью куста нефтяных скважин
EP3218700B1 (fr) 2014-11-10 2020-04-15 General Electric Company Mesure des fractions d'un fluide multiphasique
US10309910B2 (en) 2014-11-10 2019-06-04 General Electric Company System and method to measure salinity of multi-phase fluids
US10048219B2 (en) 2016-06-03 2018-08-14 Mohr and Associates Probe for indentifying and measuring volume fraction constituents of a fluid
US10119929B2 (en) 2016-06-03 2018-11-06 Mohr and Associates Method for identifying and measuring volume fraction constituents of a fluid
US10119850B2 (en) 2016-06-03 2018-11-06 Mohr and Associates Apparatus for identifying and measuring volume fraction constituents of a fluid
US11131660B2 (en) 2019-09-18 2021-09-28 Saudi Arabian Oil Company Method and apparatus to measure water content of petroleum fluids
WO2021066797A1 (fr) * 2019-09-30 2021-04-08 Schlumberger Technology Corporation Appareil de surveillance d'eau dans l'huile et procédés associés
US11422122B2 (en) 2020-06-22 2022-08-23 Saudi Arabian Oil Company Measuring water content of petroleum fluids using dried petroleum fluid solvent
US11385217B2 (en) 2020-07-29 2022-07-12 Saudi Arabian Oil Company Online measurement of dispersed oil phase in produced water
US11341830B2 (en) 2020-08-06 2022-05-24 Saudi Arabian Oil Company Infrastructure construction digital integrated twin (ICDIT)
US11687053B2 (en) 2021-03-08 2023-06-27 Saudi Arabian Oil Company Intelligent safety motor control center (ISMCC)
US11548784B1 (en) 2021-10-26 2023-01-10 Saudi Arabian Oil Company Treating sulfur dioxide containing stream by acid aqueous absorption
US12116326B2 (en) 2021-11-22 2024-10-15 Saudi Arabian Oil Company Conversion of hydrogen sulfide and carbon dioxide into hydrocarbons using non-thermal plasma and a catalyst
US11926799B2 (en) 2021-12-14 2024-03-12 Saudi Arabian Oil Company 2-iso-alkyl-2-(4-hydroxyphenyl)propane derivatives used as emulsion breakers for crude oil
US12024985B2 (en) 2022-03-24 2024-07-02 Saudi Arabian Oil Company Selective inflow control device, system, and method
US20240151564A1 (en) * 2022-11-08 2024-05-09 Schlumberger Technology Corporation Carbon dioxide multiphase flow measurement based on dielectric permittivity

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4458524A (en) * 1981-12-28 1984-07-10 Texaco Inc. Crude oil production stream analyzer
US4802361A (en) * 1982-02-08 1989-02-07 Texaco Inc. Production stream analyzer
US5103181A (en) * 1988-10-05 1992-04-07 Den Norske Oljeselskap A. S. Composition monitor and monitoring process using impedance measurements

Family Cites Families (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4441362A (en) * 1982-04-19 1984-04-10 Dresser Industries, Inc. Method for determining volumetric fractions and flow rates of individual phases within a multi-phase flow regime
FR2543687A1 (fr) * 1983-03-31 1984-10-05 Raffinage Cie Francaise Procede et dispositif pour la determination, en continu, de la teneur en l'un de ses constituants, d'un melange eventuellement heterogene
US5127272A (en) * 1991-01-03 1992-07-07 Texaco Ltd. Multiphase flow rate monitoring means and method

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4458524A (en) * 1981-12-28 1984-07-10 Texaco Inc. Crude oil production stream analyzer
US4802361A (en) * 1982-02-08 1989-02-07 Texaco Inc. Production stream analyzer
US5103181A (en) * 1988-10-05 1992-04-07 Den Norske Oljeselskap A. S. Composition monitor and monitoring process using impedance measurements

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7908930B2 (en) 2005-09-23 2011-03-22 Schlumberger Technology Corporation Systems and methods for measuring multiphase flow in a hydrocarbon transporting pipeline
EP3032230A3 (fr) * 2014-12-12 2016-06-22 General Electric Company Débitmètre et procédé d'étalonnage
US10359308B2 (en) 2014-12-12 2019-07-23 Natural Gas Solutions North America, Llc Flow meter and a method of calibration
WO2016135506A1 (fr) * 2015-02-27 2016-09-01 M-Flow Technologies Ltd Procédé et appareil de mesure d'une composition d'un fluide multiphasique
US10533955B2 (en) 2015-02-27 2020-01-14 M-Flow Technologies Ltd Method and apparatus for measuring a composition of a multiphase fluid
EA038165B1 (ru) * 2015-02-27 2021-07-16 Эм-ФЛОУ ТЕКНОЛОДЖИЗ ЛТД Способ и устройство для измерения состава многофазной текучей среды

Also Published As

Publication number Publication date
JP3228514B2 (ja) 2001-11-12
NO318642B1 (no) 2005-04-25
EP0635118A1 (fr) 1995-01-25
ATE274689T1 (de) 2004-09-15
JPH08503065A (ja) 1996-04-02
BR9306231A (pt) 1998-06-30
FI944703A0 (fi) 1994-10-07
RU94045944A (ru) 1996-08-20
NO943697D0 (no) 1994-10-04
NO943809D0 (no) 1994-10-07
US5259239A (en) 1993-11-09
FI109236B (fi) 2002-06-14
RU2114398C1 (ru) 1998-06-27
CA2117786A1 (fr) 1993-10-28
NO943697L (no) 1994-11-24
EP0635118B1 (fr) 2004-08-25
DE69333602D1 (de) 2004-09-30
FI944703A (fi) 1994-10-27
EP0635118A4 (fr) 1997-08-06
AU665919B2 (en) 1996-01-18
AU4048193A (en) 1993-11-18
CA2117786C (fr) 1998-11-17

Similar Documents

Publication Publication Date Title
US5259239A (en) Hydrocarbon mass flow meter
AU638217B2 (en) Composition monitor and monitoring process using impedance measurements
WO2000045133A1 (fr) Mesure de flux multiphase dans un tuyau
EP0628156A1 (fr) Systeme de mesure de debit
Goncalves et al. Application of the ultrasonic technique for monitoring and measuring the phase fractions of liquid-gas-solid mixtures
US3488996A (en) Determination of oil in a flowing stream
MXPA03011099A (es) Control de relacion de vapor con carbono en conversion de vapor de hidrocarburos.
JPS63500613A (ja) 多相混合物の分析
Atkinson et al. High-accuracy wet-gas multiphase well testing and production metering
Henry et al. New applications for Coriolis meter-based multiphase flow metering in the oil and gas industries
Hall et al. Use of Venturi meters in multiphase flow measurement
Joshi et al. Multiphase Measurements and Sampling—Operating Experience
Wichert Multi-Phase Flow Measurement by Orifice Meter
CN112414477B (zh) 一种多相流计量方法
Mehdizadeh et al. Multiphase meter production well testing applied to low-GOR mature fields
Gold et al. Metering of high-vapor-pressure crude oils: the case for mass measurement in shared pipeline systems
Mohamed et al. Field evaluations of different multiphase flow measurement systems
Nabil Assessment of measurement methods used in oil production
CN118148612A (zh) 一种井口液量含水测量装置及测量方法
Kilian Densitometer calibration is key to accurate NGL measurement
GIBSON 2.17 Polyphase (Oil/Water/Gas) Flowmeters
Tuss Wet gas multi-phase measurement
Bekkousha et al. Multiphase flow meters (MFPM)–Field trials and their applications in fields
HOEPPNER et al. 6.1 Density: Applications and Selection
Gysling et al. Paper 1.1 Clamp-on Two Phase Measurement of Gas Condensate Wells Using Integrated Equation of State Compositional Models

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AT AU BB BG BR CA CH CZ DE DK ES FI GB HU JP KP KR KZ LK LU MG MN MW NL NO NZ PL PT RO RU SD SE SK UA VN

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): AT BE CH DE DK ES FR GB GR IE IT LU MC NL PT SE BF BJ CF CG CI CM GA GN ML MR NE SN TD TG

DFPE Request for preliminary examination filed prior to expiration of 19th month from priority date (pct application filed before 20040101)
121 Ep: the epo has been informed by wipo that ep was designated in this application
WWE Wipo information: entry into national phase

Ref document number: 2117786

Country of ref document: CA

Ref document number: 944703

Country of ref document: FI

WWE Wipo information: entry into national phase

Ref document number: 1993911615

Country of ref document: EP

WWP Wipo information: published in national office

Ref document number: 1993911615

Country of ref document: EP

REG Reference to national code

Ref country code: DE

Ref legal event code: 8642

WWG Wipo information: grant in national office

Ref document number: 944703

Country of ref document: FI

WWG Wipo information: grant in national office

Ref document number: 1993911615

Country of ref document: EP